Drilling an oil or gas well involves two main operations: drilling and tripping. To commence the drilling procedure, a drill string terminating with a drill bit is positioned within a drilling rig and rotated such that the drill bit bores into the ground or into the seabed, in the case of offshore drilling, until it reaches a predetermined depth or penetrates a petroleum-bearing geological formation. The components of the drill string such as drill collars and drill pipe are threaded for interconnection. Depending on what type of drive system is being used, the uppermost length of drill pipe in the drill string is connected either to a kelly or to a top drive, both of which are further described hereinafter. As the drill bit advances and the top of the drill string approaches the working platform or drill floor of the drilling rig, additional lengths of drill pipe must be added to the drill string in order to advance the well further into the ground. This is accomplished by temporarily supporting the top of the drill string near the drill floor level (using devices called "slips"), disconnecting the kelly (or the top drive, as the case may be) from the top of the drill string, and then lifting a new section of drill pipe into position using the rig's elevating system and screwing it into the top of the drill string. The kelly (or the top drive) is then reconnected to the drill string, and drilling operations resume until it is again necessary to add drill pipe.
Perhaps the most common and well-known drive means for rotating a drill string is the rotary table, which is a rotating mechanism positioned on the drill floor, and which entails the use of a kelly, referred to previously. The kelly is essentially a heavy, four-sided or six-sided pipe, usually about 42 feet long or 57 feet long for offshore rigs. The rotary table has rotating bushings shaped to accommodate the kelly, plus roller bearings which allow the kelly to slide vertically through the bushings even as the rotary table is rotating. The kelly is suspended from the rig's main hoist, in conjunction with various accessories required for drilling operations (e.g., swivel, pipe elevators). With the kelly connected to the top of the drill string, the hoist lowers the drill string until the lower end of the kelly is positioned within the bushings of the rotary table. The rotary table is then activated, rotating both the kelly and the drill string connected to it, thereby turning the drill bit at the bottom of the drill string and advancing the well to a greater depth. The process of turning the drill bit to advance the hole is referred to as "making hole".
An increasingly common alternative to the rotary table is the top drive unit, which applies rotational drive at the top of the drill string, rather than at the drill floor as in the case of the rotary table. Top drive units are typically driven by either hydraulic or electric power. A significant advantage of the top drive is that a kelly is not required; instead, the drill string is connected directly to the top drive, as previously described. The top drive is supported by the rig's main hoist, and moves downward along with the drill string as drilling progresses. A rig using a top drive must provide some means for resisting or absorbing the torque generated by the top drive as it rotates the drill string, so that the top drive will be laterally and rotationally stable at all stages of drilling. This is typically accomplished by having the top drive travel along vertical guide rails built into the rig superstructure.
Tripping is a necessary but unproductive part of the overall drilling operation, and involves two basic procedures. The first procedure is extracting drill pipe from the well (referred to in the industry as "pulling out of hole" mode, or "POH"), and the second is replacing drill pipe in the well ("running in hole" mode, or "RIH"). Tripping may be necessary for several reasons, such as for replacement of worn drill bits, for recovery of damaged drill string components, or for installation of well casing.
In POH mode the kelly (if there is one) is removed temporarily, the drill string is connected to the pipe elevators, and the drill string is then pulled partially out of the hole as far as the hoisting mechanism and geometry of the drilling rig will permit. The drill string is then supported by the slips so that the section or sections of the drill pipe exposed above the drill floor may be disconnected or "broken out" and moved away from the well. The elevators then re-engage the top of the drill string so that more of the drill string may be pulled out of the hole. This process is repeated until the desired portion of the drill string has been extracted. The procedure for RIH mode is essentially the reverse of that for POH mode.
It is well known to use cable-and-winch mechanisms for hoisting and lowering the drill string and casing string during the drilling of gas and oil wells. In such mechanisms, a heavy wire-rope cable (or "drilling line") runs upward from a winch (or "drawworks") mounted at the drill floor, then is threaded through the sheaves of a "crown block" mounted high in the derrick or mast of the rig, and then down through the sheaves of a "travelling block", which moves vertically with the load being hoisted. The entire weight of the drill string, which can be several hundred tons, is transferred via the travelling block, drilling line, and crown block to the rig's derrick, which accordingly must be designed and built to withstand such loads.
A significant disadvantage of cable-and-winch rigs is that the drilling line will deteriorate eventually, entailing complete removal and replacement. This may have to be done several times during the drilling of a single deep well. Drilling line cable, being commonly as large as two inches in diameter, is expensive, and it is not unusual for a rig to require a drilling line as up to 1,500 feet long. Replacement of the drilling line due to wear accordingly entails a large direct expense. As well, the inspection, servicing, and replacement of drilling line typically results in a considerable loss of drilling time, and a corresponding increase in the overall cost of the drilling operation.
In hydraulic drilling rigs, hydraulic cylinders are used in various configurations to provide the required hoisting capability. Some hydraulic rigs also use cables and sheaves but have no winch; others eliminate the need for cables and sheaves altogether. A significant advantage of the latter arrangement is that vertical hoisting forces are not transferred to the mast, but rather are carried directly by the hydraulic cylinders. The mast therefore may be designed primarily for wind loads and other lateral stability forces only, and can be made much lighter and thus more economical than it might otherwise have been.
Whatever type of rig is being used, drilling operations require a convenient storage area for drill pipe that will be either added to or removed from the drill string during drilling or tripping. On many rigs, drill pipe is stored vertically, resting on the drill floor and held at the top in a rack known as a "fingerboard." This system requires a "derrickman" working on a "monkey board" high up in the rig, to manipulate the top of the drill pipe as it is moved in and out of the fingerboard. Other rigs use a "pipe tub", which is a sloping rack typically located adjacent to and extending below the drill floor. Drill ships and ocean-going drilling platforms often provide for vertical or near-vertical storage of drill pipe in a "Texas deck" located under the drill floor, with access being provided through a large opening in the drill floor.
When sections of drill pipe are being added during drilling, or in RIH mode during tripping, the pipe must be transported into position from the pipe storage area. The opposite applies in POH mode during tripping, when pipe removed from the drill string must be transported away from the well and then to the Texas deck. With most if not all known drilling rigs, these pipe-handling operations cannot be conveniently performed using the rig's main hoist, because the main hoist typically is centered over the well hole, and cannot be moved laterally. The pipe has to be moved laterally using either manual effort or auxiliary machinery.
Some rigs employ an auxiliary hoist to handle drill pipe. U.S. Pat. Re. No. 29,541, reissued to Russell on Feb. 21, 1978, discloses a drilling rig having a hydraulically-actuated primary hoist, plus an auxiliary hoist for pipe-handling purposes in conjunction with a fingerboard. U.S. Pat. No. 4,629,014, issued to Swisher et al. on Dec. 16, 1986, and U.S. Pat. No. 4,830,336, issued to Herabakka on May 16, 1989, provide further examples of rigs which use an auxiliary hoist in conjunction with a fingerboard. Numerous other auxiliary pipe-handling and racking systems are known in the art. These systems, however, like the Russell, Swisher, and Herabakka rigs, have a significant drawback in that they require each length of pipe to be handled twice and connected to two different hoisting mechanisms, during both drilling and tripping operations. Such double handling makes drilling operations more time-consuming and expensive.
It can readily be seen that the efficiency and economy of a well-drilling operation will increase as the amount of time and effort required for handling drill pipe is decreased. For this reason, it is desirable to maximize the length of drill pipe that a drilling rig can handle at one time during tripping or when adding pipe during drilling. Drill pipe is typically manufactured in 31-foot-long "joints." Many smaller drilling rigs are capable of handling only a single joint at a time. However, many known rigs are able to handle "stands" made up of two joints ("doubles," in industry parlance) or three joints ("triples"), and such rigs can provide significant operational cost savings over rigs that can handle only singles.
These rigs still have significant disadvantages, however. To accommodate doubles and triples, they must have taller masts. For instance, if the rig is to handle triples which are 93 feet long, the hoist must be able to rise 100 feet or more above the drill floor. The mast has to be even higher than that, particularly for a drawworks-type rig, in order to accommodate hoist machinery such as the crown block. Because of its increased height, the mast will obviously be heavier and therefore more expensive than a shorter mast, even though the maximum hoisting loads which the mast must be designed for might be the same in either case. A taller mast's weight and cost will be even further increased by the need to design it for increased wind loads resulting from the mast's larger lateral profile.
Tall, heavy rigs have particular drawbacks when used on ocean-going drill platforms or drill ships. Each floating platform or drill ship has its own particular total weight limit, made up of dead weight plus usable load capacity. Every extra pound of rig weight adds to the dead weight and reduces the usable load capacity correspondingly. Extra dead weight not only increases fuel costs for transportation, but also increases expenses for supply ships, which must make more frequent visits because the platform or drill ship has less available load capacity for storage of supplies. Moreover, ocean-going rigs generally need to be even taller than comparable land-based rigs, because they must be able to accommodate or compensate for vertical heave of up to 15 feet or more, in order to keep the drill bit working at the bottom of the hole under an essentially constant vertical load when the platform or drill ship moves up or down due to wave action.
Another problem with tall rigs in an offshore drilling context is that the center of gravity of the rig, as well as that of the entire drilling platform or drill ship, generally rises higher above the water line as the mast becomes taller. This is especially true for rigs which have heavy hoisting equipment mounted high in the mast. When seas are calm, a high center of gravity will not have a major practical effect on rig operations. In stormy conditions with high seas, however, drilling and tripping operations can become impractical or unsafe or both because of the risk of listing or even overturning. This risk increases as the rig's center of gravity rises, so a tall rig generally will have to be shut down to wait out bad weather sooner than a shorter rig would have to be shut down in the same weather.
Downtime due to weather conditions, known as "waiting on weather" time (or "WOW" time) in offshore drilling parlance, is extremely expensive. Experience in North Sea drilling operations has been that WOW time averages as much as 10% of total rig deployment time. Because the total expense of operating an offshore rig is commonly in the range of $150,000 or more per day, it is readily apparent that the pipe-handling economies made possible by offshore rigs with tall masts can be offset significantly by a corresponding risk of increased WOW time.
For all the reasons outlined above, there is a need in the well-drilling industry for a drilling rig:
(a) which is capable of handling up to triple stands of drill pipe during both drilling and tripping operations; PA1 (b) which can transport drill pipe to and from a pipe storage area using the rig's primary hoist, so as to eliminate or minimize the need for hoisting or otherwise manipulating drill pipe using auxiliary equipment or manual labour; PA1 (c) which does not require drill line, sheaves, or drawworks; PA1 (d) which does not transfer vertical hoisting loads to the rig superstructure; PA1 (e) which provides integral means for heave compensation, so as to be usable for offshore drilling operations; PA1 (f) which may be conveniently and selectively reconfigured so as to adjust the elevation of the rig's center of gravity, thereby enhancing the rig's stability when being used in offshore drilling operations; and PA1 (g) which is significantly lighter in weight than known rigs capable of operating with triple stands of drill pipe. PA1 (a) a rig substructure comprising a drill floor having a drill opening; PA1 (b) at least three structural towers fixedly mounted to the rig substructure and projecting vertically above the drill floor, said towers being in spaced relationship to each other and encircling the drill opening; PA1 (c) a plurality of hydraulically-actuated, telescoping lifting rams corresponding in number to the number of towers, said lifting rams being fixedly mounted at their lower ends to the rig substructure and projecting vertically above the drill floor, and each lifting ram being in proximal association with one of the towers; PA1 (d) lateral support means associated with the towers for providing lateral support to the lifting rams throughout their range of telescoping operation; PA1 (e) hydraulic power means for actuating the lifting rams such that the lifting rams may operate substantially in unison; PA1 (f) a roof platform affixed to and supported by the upper ends of the lifting rams, said roof platform comprising a substantially horizontal cradle track; PA1 (g) a cradle having means for engaging the cradle track such that the cradle may be mounted to and moved along the cradle track; PA1 (h) cradle actuation means mounted to the roof platform, for moving the cradle along the cradle track; and PA1 (i) a drilling hook associated with the cradle, for vertically supporting a drill string plus accessory components and pipe-handling tools or service equipment. PA1 (a) providing a drill rig comprising a drill floor with a drill opening, a drill pipe storage area associated with the drill rig, and a rotary top drive movable vertically and horizontally; PA1 (b) supporting a drill string positioned in the drill opening, and disconnecting the top drive from the drill string; PA1 (c) raising the top drive clear of the drill string; PA1 (d) moving the top drive laterally from a position over the drill opening to a position over the drill pipe storage area; PA1 (e) lowering the top drive and connecting the top drive to a drill pipe section from the drill pipe storage area; PA1 (f) raising the top drive such that the bottom of the drill pipe section is higher than the top of the drill string; PA1 (g) moving the top drive laterally to a position over the drill string; PA1 (h) connecting the drill pipe section to the top of the drill string; and PA1 (i) recommencing drilling operations.